North Dakota – update until 2015-11

This is the first attempt to provide an interactive presentation of the oil production in North Dakota. Note that you can click through the different analyses by using the blocks at the top. Furthermore, each analysis is interactive: the filters can be easily changed (there is an apply button at the bottom of each filter to enact it), and tooltips are available when the mouse is hovering over parts of the presentation.

The reason for these efforts is my perception that there are a lot of questions and misconceptions about the shale oil production in the U.S., but that detailed, accurate, objective, comprehensive, up-to-date and well-presented information is lacking.

I would like to bridge that gap.

The idea is to add further interactive analyses to the existing ones above that provide other and more detailed insights.

Furthermore, I would like to include other shale oil producing regions, such as the Niobrara, as well. Currently I don’t have access to detailed well data for the Eagle Ford and the Permian, so those fields will not be included soon.

All the basic data for North Dakota is provided by the NDIC. This data has been analyzed, and further enriched. For example, for confidential wells, the “runs” data is used as a proxy for oil production.

Eventually I would like to add a layered subscription service for all the advanced analyses, while keeping several interactive analyses free for all as a public service. The reason for this future introduction of a subscription service is to be able to cover the costs of several advanced third party tools and data sources, and to maintain a high level of quality, with regular updates and improvements.

Any comments on these efforts are highly appreciated. Furthermore, any suggestions on how further value can be added through this way of presentation are very helpful.

I would like to keep all discussion civil and on topic, and reserve the right to remove comments that are in violation of these rules.

My gratitude goes to Martijn Muurman for his extraordinary coding skills, input, and efforts to realize this presentation.

Edit: I received some questions about how to interact with the presentation. I will provide 2 use cases that further clarify this.

1. You want to know how much the wells of Continental Resources have improved over the years. => Left-click on the block “Well quality over the years”, click on the “operator” filter, click on “all” to empty the filter, click on “Continental Resources” to filter only its wells, and click on “apply” at the bottom of the list. You will now see the type curve & cumulative curve for the average Continental Resources well in ND, for each of the past years. You can add additional filters.

2. You want to know how much new production EOG has been bringing online. => Left-click on the block “How much is produced?”, select only “EOG” by deselecting all, and then checking EOG, followed by apply. You can see that the current output from EOGs wells that started in 2015 is just a little higher than the current output from wells that started in 2014 or 2013.

Note that in both of these cases you will see the gross operated production volumes, which will differ from actual reported company production volumes. If you need some assistance with other questions, let me know.

Great site. You know it is. Not kissing your ass. Keep up the great work, man!

I think it would be enriched by some discussion by you of the implications or different cuts. Basically the things you do as posts anyway. Both new ideas or responses to questions and then just the monthly update style things. Probably a blog is the right format. It makes things searchable easily by Google (rather than buried comments elsewhere). And then a lot of your stuff seems like monthly updates, so that format fits well. [Even the more one off analyses, will tend to have some time dependency as they would obviously change at least a little with another year’s data or the like.]

I think Dean and Alex have great amateur analysis content also. Would love to have them participate in some way (as commenters at least).

Suggestion: Please keep the discussion more focused on interesting questions of oil and gas. No global warming or electric cars. (Nothing wrong with those topics, but let it be somewhere else.)

Gross: there is a difference (the exact “interest” an operator has in the well) between the total volume produced by a well, and the part of the volume that belongs to the operator. Furthermore, these companies may also have non-operated interests (they don’t operate the well). I just highlight this, as these are reasons why there are some differences between the volumes shown here, and the volumes reported by these companies.

Thanks for your other input as well. I do want to focus on supplying the data through these interactive presentations, but will provide some comments as well based on what I catches my eye.

I agree that Dean and Alex have provided great content (I would not call it amateuristic!), and hope they keep doing so, here or elsewhere.

One part would be the interactive thing we have here. [A good add, here would be some posts describing each of the major levers: formations, fields, operators. This is a bit of work, but really useful for orienting the reader. Not expecting you to write a profile on every LLC with a well, but maybe a pie chart of operator production and then some basic discussion of the main operators, with a link to their website. The “field” thing is also a little strange as USGS really considers the whole thing a continuous resource. I wonder if that is a little more administrative how ND divides the townships. I actually think it is a little more useful to think of larger “spots” than the fields (anticline area, Divide county spot, Elm Coulee, etc.)

The other part would be a time-based blog postings (more journal-like).

If you add Niobrara, that could be a trifurcation, but basically similar to Bakken.

Enno
Just redirected here from Bruce Oksol’s blog. He expressed profusive praise for your work. Three thumbs up from me.

A pool is the term the NDIC uses to describe which formation is being targeted, eg., the Spearfish, Tyler, Madison, Red River, Bakken, TF.
It is easy to overlook the fact that 50,000 bbl/day is produced conventionally from ND.

A field is a legacy-tyoe area from conventional wells dating back to the early ’50s. Great efforts are put into these delineations as a LOT of money is involved in preventing the takings of another’s “milkshake” from conventional reservoirs/drilling.

Do I understand correctly then that what I show above in the filter “Field name” is actually a combination of a field (or location) and a pool?
The first part is available in the NDIC datafiles with the name “field_name”, e.g. Parshall, Sanish, Alger.

Enno
The field name is the relatively small area from which the wells are drilled into the desired formation/’pool’.

Example, I just pulled up the October production report. First four listings are Alexander-Bakken, Alexander-Duperow, Alexander-Madison, Alexander-Red River.
All these wells are located in the Alexander field and target the described formation(pool).
At the lower left of each listing is the total wells for that pool.
BTW, those long monthly reports are alphabetized first by field name then by operator. Confidential well results are first listed for all fields.

No funky stuff going on – what is not so intuitive in the type curve graphs is that there are fewer wells at the end of the tails, and that can lead to more fluctuation. e.g. Not all CLR wells that started in 2015 have reached already 8 months of production (only the wells starting in Jan to April 2015 have). Therefore, it is a good strategy to ignore the last few data points in those graphs, or at least understand that they can fluctuate heavily when more data comes in.

Also note that I show the data based on calendar months, as I don’t have accurate data for all production data regarding the exact number of producing days. This may slightly differ if you calculate only based on actual producing days, especially for the first month.

Was wondering about how to estimate well EURs. I guess what you know for sure are the profiles so far known cums). Then it is an estimate of the tails. For CLR, if I look at their “good” years (2011, 14, 15) and just go with 2011, I get ~200,000 for 2011 (5 years production). If I guess 5 years at an average of 40 (starting at 65 and declining to 25 or so, nonlinearly). Then that’s an extra 73,000. Then if I figure another 40 years at an average of 15 (say going from 25 to 10 nonlinearly), then that’s 219,000. So for a 50 year well, something like a 500,000 type curve.

I have decided for myself that I will (try to..) ignore reported EURs.

The reason is that, as Ciaran has nicely shown, about 80-90%, of the NPV of a Bakken well is captured in the first 5 years. Of course this assumes that prices will not rise much, or just follow the strip. In comparison, it could be that the EUR of a well is double the cumulative production of the first 5 years.

I think that EURs, together with 24hour/30day IP rates and BOE reporting, are metrics that are provided by many shale companies, but are not useful for determining the economics. They all seem to have the effect to nudge the perceived performance of shale wells to a higher level than the actual performance.

Based on the data so far (incl wells from 2007-2009), if you exclude wells that have been refracked, decline rates for Bakken wells seem to stay above 10% per year.

Enno; as always, thank you for your good work. I look forward to working with you more on net revenue interest and how it pertains to reported gross production and Bakken economics.

I applaud you for withholding comment on the EUR fluff that the shale industry is notorious for. Your realized production profiles are all anyone needs to see to begin to understand how bleak the situation currently is. At $30.00 gross well head prices in the Bakken, $20.00 net, before OPEX, a typical completed well will currently require over 875,000 gross BOE to reach payout. “Hoping” for higher oil prices will not magically get very many new wells now being drilled in the Bakken to payout, much less profitable. Nothing occurring in that shale play in North Dakota at the moment makes any economic sense whatsoever.

The wells decline exponentially after about 10 years at about a 10% annual rate, prior to that you can fit a hyperbolic profile to the data using least squares. For the average Bakken/Three Forks well the EUR is about 250 to 300 kb of oil. The gas does not add a lot of profit so I ignore the gas.

FWIW, saw an interesting slide in the Gulfport company presentation (monthly, in appendix). They actually gave all the parameters for their type curve. Thought that was very straight–can just do your own sensitivity analysis or the like, then.

They’ve been talked about a fair amount in terms of doing objective analysis. Most of talk was pretty basic, but still interesting technically, related to their methodology for reservoir analysis. Very easy to follow.

They did shed a little light on their projections in terms of economics. They tend to be pretty negative, like David Hughes. But then how do you explain the low gas prices (not just the prompt but the strip)? [And it’s actually been dropping over the last year, not going up, not correcting. The strip would imply shale has a lot more legs at low price than their work does.] They mentioned how old some of their data is and that technology has improved in terms of economics (long laterals) and output (completion optimization). Also mentioned that prices for drilling and completion services have gone down. Said that their study could probably be lowered by 0.50 cents for the output levels at different prices. Didn’t think anything in the H made money at $2, but a few parts could at $2.50, more at $4.

Their Marcellus work is not out yet, but they see the Marcellus as much bigger than the Haynesville and think the H is decent sized.

How many rigs do you think it takes to keep production flat? Assume no change in rig productivity (improvements in completion and efficiency are perfectly matched by the need to move to more marginal rock). Disregard DUCs.

I estimate that about 110 wells per month are needed to keep production at about 1.15 mbo/d.

Rig productivity has increased during the last 9 months of 2015 from about 1.1 wells/rig/month (2014) to about 1.4 wells/rig/month. This increase probably happened due to several factors (better rigs/crews were kept, and other efficiencies like pad drilling and focusing drilling on smaller areas). I don’t expect a very big increase from here anymore, at least not in the coming year.

That means about 80 rigs are needed to keep production flat (at 1.15 mbo/d), ignoring DUCs.

Because the DUC count seems to have increased in Dec & Jan, and fewer than 90 wells/month were drilled in Dec & Jan (besides the oil price, completion is also normally at lower levels during winter months), I expect that the production decline has increased during these months. I estimate March production in ND to be very close (+-0.03 mbo/d) to 1.10 mbo/d.

Production is not provided for confidential wells. However, “runs”, which is the actual oil volume in sales from the wells IS provided for confidential wells. This is a very close proxy (the difference is what is left in the tanks at the well I imagine). I think I have estimated in the past the difference to be on average about 1000 barrels for a well. That means that I slightly under report actual production due to this issue, for wells that were confidential..

The formation is also not provided, initially, for confidential wells. I have put them all in the “Confidential” formation, so it is easy for everybody to decide whether to include them or not. Almost all of the confidential wells are drilled in the Three Forks and Middle Bakken formations, as is also indicated by the Director cuts from the NDIC.